Oil wells (wellbores) are usually drilled with a drill string. The drill string includes a tubular member having a drilling assembly that includes a single drill bit at its bottom end. The drilling assembly typically includes devices and sensors that provide information relating to a variety of parameters relating to the drilling operations (“drilling parameters”), behavior of the drilling assembly (“drilling assembly parameters”) and parameters relating to the formations penetrated by the wellbore (“formation parameters”). A drill bit and/or reamer attached to the bottom end of the drilling assembly is rotated by rotating the drill string from the drilling rig and/or by a drilling motor (also referred to as a “mud motor”) in the bottom-hole assembly (“BHA”) to remove formation material to drill the wellbore. A large number of wellbores are drilled along non-vertical, contoured trajectories in what is often referred to as directional drilling. For example, a single wellbore may include one or more vertical sections, deviated sections and horizontal sections extending through differing types of rock formations.
When drilling with a fixed-cutter, or so-called “drag” bit or other earth-boring tool that progresses from a soft formation, such as sand, to a hard formation, such as shale, or vice versa, the rate of penetration (“ROP”) changes, and excessive ROP fluctuations and/or vibrations (lateral or torsional) may be generated in the drill bit. The ROP is typically controlled by controlling the weight-on-bit (“WOB”) and rotational speed (revolutions per minute or “RPM”) of the drill bit. WOB is controlled by controlling the hook load at the surface and RPM is controlled by controlling the drill string rotation at the surface and/or by controlling the drilling motor speed in the drilling assembly. Controlling the drill bit vibrations and ROP by such methods requires the drilling system or operator to take actions at the surface. The impact of such surface actions on the drill bit fluctuations is not substantially immediate. Drill bit aggressiveness contributes to the vibration, whirl and stick-slip for a given WOB and drill bit rotational speed. “Depth of Cut” (“DOC”) of a fixed-cutter drill bit, is generally defined as a distance a cutter affixed to a bit penetrates a formation being drilled, and may also be characterized by a longitudinal distance a bit advances into a formation being drilled over a revolution of the bit, both parameters being indicative of the drill bit's aggressiveness. Controlling DOC can prevent excessive formation material buildup on the bit (e.g., “bit balling,”), limit reactive torque to an acceptable level and avoid loss of tool face and stick/slip of the drill string, enhance steerability and directional control of the bit, provide a smoother and more consistent diameter borehole, avoid premature damage to the cutting elements, and prolong operating life of the drill bit.